In the art of recovering hydrocarbon values from subterranean formations, it is common, particularly in formations of low permeability, to hydraulically fracture the hydrocarbon-bearing formation to provide flow channels to facilitate production of the hydrocarbons to the wellbore. Fracturing fluids typically comprise a thickened base fluid which primarily permits the suspension of particulate proppant materials in the fluid. These proppant materials, typically sand, sintered bauxite or the like, will remain in place within the fracture when fracturing pressure is released thereby holding the fracture open. Such thickened fluids also aid in the transfer of hydraulic fracturing pressure to the rock surfaces and help to control leak-off of the fracturing fluid into the formation.
Of necessity, fracturing fluids are prepared on the surface and then pumped through tubing within the wellbore to the hydrocarbon-bearing subterranean formation. While high viscosity is a desirable characteristic of a fluid within the formation in order to efficiently transfer fracturing pressures to the rock as well as to reduce fluid leak-off and provide for the suspension of proppants, large amounts of hydraulic horsepower are required to pump such high viscosity fluids through the well tubing to the formation.
The most common type of fracturing fluid comprises a polymer thickened base fluid wherein the thickening polymer comprises a galactomannangum, a cellulosic polymer or a synthetic polymer. To increase the viscosity and, thus, the proppant carrying capacity as well as to increase high temperature stability of the fracturing fluid, cross-linking of the polymers is commonly practiced. Typical cross-linking agents comprise soluble organo metallic salts. Metal ions provide for cross-linking or tying together of the polymer chains to increase the viscosity and to improve the theology of the fracturing fluid. In order to reduce the pumping friction pressure in such fluids, various methods of delaying cross-linking of the polymers have been developed. This allows the pumping of a relatively less viscous fracturing fluid having relatively low friction pressures within the well tubing with cross-linking being effected at or near the subterranean formation so that the advantageous properties of the thickened cross-linked fluid are available at the rock face.
One difficulty with polymer-thickened fluids is the deposit and retention of polymer residues at the rock face and within the proppant pack which can reduce the effectiveness of the fracturing operation. While there have been significant advancements in the use of oxidative or other breaker systems to reduce the effects of a polymer filter cake and other polymer residue within the fracture, such methods are never one hundred percent effective in cleaning the fracture.
One means of overcoming the effects of polymer residues remaining within a fracture would be to use a fracturing fluid comprising fluids which are compatible with existing formation fluids. Thus, various emulsions of water and oil have been proposed.
U.S. Pat. Nos. 3,710,865 and 3,977,472 have taught the use of stabilized oil-in-water emulsions as fracturing fluids. In these systems, the internal oil phase typically constitutes fifty to eighty volume percent of the emulsion. The water external phase is stabilized by adding a water dispersible polymeric thickening agent. The difficulty with these systems is that they are costly because they use relatively large amounts of oil and, since water dispersible polymeric thickening agents are used, the problem of polymer residues within the completed fracture still remains.
One approach to overcoming the use of costly oil in a water external emulsion for hydraulic fracturing, acidizing and other well treatment applications has been to use an oil-external or water-in-oil emulsion. Such oil-external emulsions generally comprise only about ten to thirty volume percent oil as opposed to the fifty to eighty percent oil typically found in water external emulsions. However, the major disadvantage of an oil-external emulsion which severely limits its use is its extremely high viscosity resulting in high frictional resistance to flow down well tubulars. This increased friction pressure is due to the high viscosity which such oil-external emulsions develop at low temperature. U.S. Pat. 3,387,074 describes a technique for overcoming the problem of high friction pressures in the pumping of viscous water in oil emulsions by providing a lubricating annulus of water which forms a physical barrier between the viscous emulsion and the well tubulars thereby considerably lowering the friction pressure drop in the pumping of these fluids. However, this technique requires the use of special wellhead equipment and fittings to create the conditions necessary to form the annular film of water between the viscous emulsion and the tubular wall.
Another means for overcoming the high friction pressure in pumping a viscous water-in-oil emulsion is described in U.S. Pat. No. 4,233,165. In this system, a water-in-oil emulsion in amounts of thirty to ninety-five percent by volume are dispersed in an aqueous medium to reduce the overall viscosity and friction pressure of the resultant dispersion to create a water-in-oil-in-water emulsion. The complications of this dual step dispersion process are apparent.